UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

REGION IX

75 Hawthorne Street San Francisco, CA 94105



## MEMO

SUBJECT: GHG BACT Analysis Addressing Pr e-Combustion Carbon Capture and Storage/Sequestration (CCS) for the SPI-Anderson Permit Project

TO: SPI-Anderson PSD Permit Administrative Record

FROM: Shaheerah Kelly, Environmental Engineer U.S. EPA, Region 9, Air Division, Permits Office

DATE: April 25, 2014

The attachment to this memo is an addendum to the Supplemental Statement of Basis and Ambient Air Quality Impact Report for Gree nhouse Gas (GHG) Emissions dated November 2013 (GHG AAQIR). This addendum supplements EPA’s Best Available Control Technology (BACT) analysis for GHG in Sec tion 5 of the GHG AAQIR.

AttachmentGHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project April 2014 Page 2 

## GHG BACT Analysis Addressing Pre-Combustion Carbon Capture and Storage/Sequestration (CCS) for the SPI-Anderson Project

In the Supplemental Statement of Basis and Am bient Air Quality Impact Report for Greenhouse Gas Emissions dated November 2013 (GHG AAQIR), EPA’s evaluation stated that there are three approaches to CO 2 capture that are generally applic able to power generation: (1) precombustion systems designed to separate CO 2 and hydrogen (H 2 ) from produced syngas, (2) post-combustion systems designed to separate CO 2 from flue gas, and (3) oxy-combustion that uses high-purity oxygen (O 2 ) instead of air, which produces flue gas composed largely of CO 2

. We stated that the use of a pre-combustion sy stem would require a gasification unit to produce syngas from the biomass fuel, which would amount to redefining the source. However, we are revising this determination base d on additional information we r eceived from the applicant and our independent research.

Step 1 – Identify Available Control Technologies

EPA is including pre-combustion CCS as a control alternative for the proposed biomass boiler.

Step 2 – Eliminate Technically Infeasible Control Technologies

A pre-combustion CCS system is a complex syst em comprised of a group of technologies that

remove CO 2 (i.e., pre-combustion CO 2 capture) before the combustion of the hydrogen-rich fuel produced in this system, and transport and storage (or sequestration) of the CO 2 gas. Such a system would be used instead of the proposed st oker boiler for producing el ectricity for the grid and steam for SPI’s lumber operation.

Pre-Combustion CO 2 Capture

The pre-combustion CO 2 capture would involve the followi ng processes: gasification plant (which includes preparation of the biomass feedst ock); raw gas cooling (via water quench or heat recovery systems); water-gas shift reactor; gas cleanup; air separation unit (ASU); and CO 2 removal.

Gasification plant: Gasification involves heating so lid biomass in an oxygen-starved environment to produce a low or medium calorific gas. The gasification plant generally would consist of a gasifier and a natura l-gas- or oil-fired heater for h eating the gasifier to a certain temperature, as well as equipment for pr eparing, processing, and conveying the biomass feedstock. Preparation of the biom ass feedstock is not expected to be a significant change for the SPI facility. The biomass feed stock, with the addition of stea m and oxygen, is charged to the gasifier. An ASU is used to generate the en riched oxygen supply necessary for the gasification process. During gasification, the biomass is conve rted to gaseous products and char and/or ash at high temperatures. Depending on a number of variables such as feedstock characteristics, temperature and gasifying agent (e.g., use of ai r, oxygen, and/or steam), the composition of theGHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project April 2014 Page 3 gaseous products can consist of car bon monoxide (CO), carbon dioxide (CO 2 ), hydrogen (H 2 ), methane (CH 4 ), nitrogen (N 2 ), as well as non-gaseous byproducts such as char and tars. At gasification temperatures above 1275°K (1835°F) the resulting gas stream consists primarily of

CO and H 2 called synthesis gas or syngas. At rela tively lower gasification temperatures, other components such as methane and higher hydrocarbons (tars) are also present in the resulting gas stream, and this is often referred to as producer gas. (Carbo, Michiel, Global Technology Roadmap for CCS in Industry, Biomass-based industrial CO 2 sources: biofuels production with

CCS at 13-14). For purposes of this analysis, we re fer to the gas exiting the gasifer as “raw gas.”

Raw gas cooling: The raw gas exiting the gasifier is sent to a water quench or similar process to cool the gas down. The gas needs to be sufficiently cooled so that it can be sent directly to the gas clean-up. If the gasifier has a high gas outle t temperature, the heat from the raw gas may be used to generate steam for the steam turbine. If a combined cycle gas turbine operation is used, a steam turbine is supplied with steam from th e gas turbine heat recovery steam generator (HRSG).

Gas cleanup system: Typically, syngas must be thoroughl y cleaned prior to further use, especially if it will be used in a combustion turb ine. The gas cleanup process consists of initially removing particulates, soot and heavy metals. Subsequently, ot her compounds are removed such as tars, acid gases, and sulfur-containing comp ounds. The degree of cleanup will depend of the combustion unit employed. For instance, more cleaning may be needed if the gas is burned in a gas turbine rather than a gas boiler.

Water-gas shift reactor: The gas exiting the gas cleanup system is sent to a water-gas shift reactor. This pro cess converts CO to CO 2 , and is generally necessary for CO 2 removal. The water-gas shift involves the catalyt ic reaction of CO and steam. Si nce the gas initially contains primarily CO and H 2 , this shift reaction diminishes the co ncentration of CO and enriches the

concentration of H 2 in the pre-combustion raw gas st ream via the following reaction.

ܪ ൅ ܱܥ ଶ ܱ ∆ ܱܥ	 → ଶ ܪ	൅ ଶ .

CO 2 Removal: CO 2 -laden clean gas exiting the water-shift reactor is then sent to an absorber

where CO 2 is removed from the gas stream. This CO 2 gas is compressed, and transported via pipelines for storage and sequestration.

Combustion of Hydrogen-rich Gas

The resulting clean gas is primarily H 2 gas, or hydrogen-rich gas, can be burned in a gas boiler to produce steam, or in a combin ed cycle turbine generator sy stem to produce both steam and electricity. The clean gas is mixed with nitroge n (for flow control, flame stabilization and NO x reduction) and/or diluted with water before it is supplied to the gas turbine combustion chamber or boiler. Depending on the availability of hydrogen-rich gas, the combustion unit can (1) combust hydrogen-rich gas alone, (2) co-fire hydrogen-rich gas a nd natural gas, or (3) naturalGHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project April 2014 Page 4 gas alone (e.g., during periods of startup, shutdown, or upset periods, or when the supply of hydrogen-rich gas is intermitte nt or not available).

Carbon Capture and Storage of CO 2

Captured and compressed CO 2 must be transported via CO 2 pipelines to a storage facility or end use, such as enhanced oil recovery (EOR). California Department of Conservation Division of Oil, Gas & Geothermal Resources (DOGGR) over sees the drilling, operation, maintenance, and plugging and abandonment of oil, natu ral gas, and geothermal wells in the state. There are 6 oil and gas districts in California (see Figure 1). Sh asta County is located in District 6, which is comprised of the northern Ca lifornia counties.

Figure 1: Oil and Gas Distri ct Boundaries in California

Source: California Oil & Gas Fields, Volume 1 - Central California, California Department of Conservation Divisi on of Oil, Gas, and Geothermal Resources

DOGGR provides publications and other informati on on individual oil fiel ds and the EOR work

done in each. There are several oil and gas fields located in northe rn California. Most of these fields contain gas wells, and do not produce oil. There are no oil and gas fields in Shasta CountyGHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project April 2014 Page 5 (see Figure 2). Furthermore, there are curren tly no EOR activities in the oil fields within

District 6. 1 There are EOR activities in Districts 1 th rough 5 in central and southern California.

Figure 2: Oil and Gas Wells/Fields in Northern California

Source: DOGGR Well Finder at http://maps.conservation.ca.gov/doggr/index.html

Technical Feasibility

Because the source category for identifying potentia lly available control tec hnologies in Step 1 is broad, certain technologies may be determined in feasible under Step 2 when the particular physical, engineering and chemical processes of the proposed sour ce are considered in more detail. The analysis in Step 2 may review wh ether a technology has been “demonstrated”, which is generally established if the technology has been installed and ope rated successfully elsewhere. If the technology has not been demonstrated, it ma y still be technically fe asible if the technology is both “available” and “applicable.” ( See NSR Workshop Manual , Draft, October 1990 at B.17.)

Commercial CCS, including pre-combustion CCS, ha s been planned for a number of coal-fired power generation and industrial appl ications. The industr ial applications are projects in the gas

1 See California Oil & Gas Fields, Volume III – Northern California = oil/gas wellNEVADA

Anderson CALIFORNIAGHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project April 2014 Page 6 processing and chemical production indus tries, where the separation of CO 2 is part of the process design. Pre-combustion CCS is currently “demonstrat ed in practice” at facilities such as Dakota Gasification and Coffeyville Fertilizer. In ad dition, several pre-combustion CCS projects are currently being proposed in the Unit ed States, and a number of these projects in the United States are demonstration projects being fu nding by U.S. Department of Energy. 2 The equipment used to accomplish pre-combustion CCS at these facilities is currently available and applicable to the biomass feedstock at the SPI-Anderson facility.

EPA has not considered the BACT requirement as a means to redefine the design of the facility when considering available contro l alternatives. In considering this, EPA looks at whether the control option substantially alters the purpose or basic design of the proposed facility that it

should be considered a redefinition of the sour ce. SPI’s primary business is operation of a lumber production facility. An integral part ofthe facility is providing steam to eight steamheated, double-track, kilns used for drying lumber. SPI may accomplish continuous steam production to the kilns by storing hydrogen-rich gas produced in the gasification operation and burning the stored gas at a later time or by bur ning natural gas when hydrogen-rich gas is not available. Thus, EPA is revi sing its previous determination regarding pre-combustion CCS, and we have determined that this technology is techni cally feasible for the boiler project at the SPIAnderson facility.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Pre-combustion CCS has been primarily proposed for projects that use coal or petcoke as a fossil fuel. DOE evaluated three proposed fossil fuel f eedstock IGCC power plan t configurations with carbon capture, and determined that the GE Ener gy facility could achie ve 90.2 percent reduction

of CO 2 in syngas, the Conoco Phill ips facility could achieve 88.4 percent reduction of CO 2 in syngas, and the Shell facility coul d achieve 90.8 percen t reduction of CO 2 in syngas. 3 The Hydrogen Energy California (HECA) project, a fo ssil fuel feedstock IGCC power plant proposed near Bakersfield, California, is also projected to achi eve 90 percent reduction of CO 2 in syngas. 4

Based on this information, an approximate 90 percent reduction of CO 2 in the gas stream can be expected for a prep-combustion CO 2 capture system, and is consid ered to be a “full capture” CCS system. A “partial capture” CCS system achieves some level le ss than 90 percent of capture. Regardless of whether “ful l capture” or “partial capture” of CO 2 from the gas stream is employed, CO 2 compression, transportation (i.e., through pipelines) and stor age (i.e., geologic sequestration or use in EOR) will be needed.

2 See http://sequestration.mit.edu/tools/projects/index_capture.html and http://www.netl.doe.gov/researc h/coal/major-demonstrations/clean-coal-power-initiative

. 3 See Cost and Performance Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May 2007.

4 See Notice of Final Determination of Compliance (FDOC) for Hydrogen Energy California Facility: 5-7616, Project: 1121903, Issued July 8, 2013.GHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project April 2014 Page 7 Our GHG AAQIR included a table of recent GHG BACT determinations made at similar facilities according to the RA CT/BACT/LAER Clearinghouse (RBL C), as well as other permit determinations not included in the RBLC. ( See Table 5-8 of the GHG AAQIR.) There are no

similar biomass facilities that current ly use pre-combustion CCS for reducing CO 2 emissions.

Step 4 – Evaluate Most Effective Controls

As previously mentioned above, the resulting clean gas is primarily H 2 gas, or hydrogen-rich gas, which can be burned in a gas boiler to produce st eam, or in a combined cycle turbine generator system to produce both steam and electricity. A co mbined cycle gas turbine (i.e., an integrated gasification combined cycle or IGCC facility) is mo re efficient since it can be used to generate electricity using a gas turbine and steam turbin e which is supplied steam produced in a heat recovery steam generator (HRSG).

However, the facility may have to burn natura l gas, or burn both natu ral gas and hydrogen-rich fuel during periods when hydrogen-ri ch fuel is low or is not avai lable (e.g., during maintenance, startup, shutdown, or upset of the gasification pl ant. This scenario would produce additional

GHG emissions.

The CO 2 capture and compression system will decrease the facility’s thermal efficiency due to the additional parasitic energy load from the CO 2 capture system. The parasitic load can occur in a number of places, including extraction of steam from the HRSG for operation of reboilers and providing electricity to drive the CO 2 compressor. The drop in thermal efficiency with capture has multiple effects which include burning more biomass to produce the same amount of steam and electricity to meet the fac ility’s business needs. This has the effect of producing more GHG

emissions.

As previously mentioned above, regardless of whet her “full capture” or “partial capture” of CO 2 from the clean raw gas from the gasification process is employed, CO 2 compression, transportation (i.e., through pipe lines) and storage (i .e., geologic sequestration, or for use in EOR) will be needed. Captured and compressed CO 2 must be transported to a storage facility (deep saline formation) or for end use (EOR).

There are no nearby petroleum extr action operations or industrial pro cesses that would be able to accept the volume of CO 2 SPI is expected to emit. CO 2 injection would have to occur at an EOR operation located in central or sout hern California. SPI considered the cost of EOR at an oil field in Brentwood, California, approximately 25 mile s west of Stockton, California, and estimated

that the cost of constructi ng a pipeline to transport CO 2 from the Anderson facility to Brentwood, California would cost approximately $109,907,547. 5 Given that the cost of the project without gasification and CCS is $75,000,000, the pipeline cost represents a significant increase in the cost of the project, and the overall pre-combus tion CCS costs would only increase if the cost

5 SPI Anderson email response to EPA dated September 14, 2013.GHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project April 2014 Page 8 associated with CO 2 capture equipment and the more likely transport of SPI’s CO 2 to an EOR operation in central or southern California are considered. Acco rdingly, and for reason similar to those provided for post-combus tion CCS discussed below, we are eliminating pre-combustion CCS using EOR as a GHG control option due to its disproportionate costs.

Step 5 – Select BACT

EPA has not changed its overall BACT determina tion for this facility based on the analysis below, since pre-combustion CCS is excluded as BACT in Step 4. Specifically, we continue to conclude that BACT for the proposed bioma ss-fired stoker boiler is (1) 0.36 pounds of CO 2 e per pound of steam (12-month rolling average basis), (2 ) combustion of biomass at all times except during periods of startup, shutdown and flame stab ilization (in which natural gas fuel is allowed to be combusted), and (3) energy efficient design and use of good combustion and operational and maintenance practices as described in SPI’s permit application and subsequent submissions to the EPA, which include, but are not limited to , (i) construction and operation of an efficient, state-of-the-art, air-cooled, r eciprocating stepgrate stoker boil er that ensures good combustion; (ii) operation of the boiler as a cogeneration un it; and (iii) operation and maintenance of the

boiler in accordance with the manufacturer’s recommendations. The CO 2 e limit applies at all times, including during startups and shutdowns.